The present invention relates to the signalling of downhole conditions in oil wells and the like.
Knowledge of the conditions in a well bore is of vital importance in well operations. Such conditions may include the depth of tools and equipment and the is end of a well string, pressure or temperature crossing a particular threshold, a valve in such equipment opening or closing, or the last gun in a string firing.
Some conditions can be determined from the surface, as for example the depth of tools and equipment. Direct methods that are used include measuring the length of pipe joints as they are run in hole, and a measuring wheel running against cable or continuous pipe.
These methods are largely “dead reckoning” techniques which involve only surface measurements. The disadvantage of these methods is that they do not involve any detection of downhole features, so they depend on pre-existing knowledge of the hole characteristics.
Since the layers of rock formation are fixed, it is also possible to correlate depth against a log of some physical property of the rock formation. In practice it is usual to compare an electric wireline log of natural gamma ray intensity with a log showing where the joints are in the steel casing that is used to line the well bore. This method means that subsequent runs can use a relatively simple casing collar log only, without having to log the actual formation properties again. A similar technique is to tag a feature of known depth in the well bore.
Some of these methods involve measuring downhole conditions. The disadvantage of these latter methods is that an electric wireline to surface is required to transmit the signal measured. This is not always convenient. Example of this are when running jointed pipe or when running continuous pipe (coiled tubing) without an integral electric line incorporated, or when running stranded/slickline operations.
It is known to use acoustic signal transmission techniques to overcome this problem. Thus Schlumberger/Flowers et al, U.S. Pat. No. 6,604,582, uses an acoustic transmitter comprising a flow based signalling system using a flow diverter to generate pressure pulses which can be detected at surface. Halliburton/Connell et al, U.S. Pat. No. 6,305,467 also uses a flow based system using a solenoid valve. Baker Hughes/Mendez et al, U.S. Pat. No. 6,896,056, uses acoustic signalling with transmission up the pipe or tubing to the surface. (All these systems contemplate CCL (casing collar location) as the, or one of the, conditions in the hole which are detected and so signalled to the surface.)
There is also a German patent document, DE 37 03 244, Bergwerksverband, which uses a system involving signalling through the water surrounding the drilling pipe. The transmitter is pointed down the column of water, and the receiver is mounted pointing up the column (or vice versa). The transmitter uses a spark gap mounted at the focus of a hollow paraboloid to focus the waves up the drilling pipe hole, and a receiver at the top. This is an improvement on an earlier system which did not use focussing of this kind.
All these systems have potential disadvantages. In the Schlumberger and Halliburton systems, a fluid flow path is required to surface, debris in the system can block the ports, and the fluid flow path has to circulate through the tool. In the Baker Hughes system, the tubular pipework needs to extend continuously to the surface, and profile and/or material changes in the tubular piping can affect signal strength. The same holds for the Bergwerksverband system and its predecessor.